Oilfield drilling fluid, often called “mud,” serves multiple purposes in the industry. Among its many functions, the drilling mud acts as a lubricant to cool rotary drill bits and facilitate faster cutting rates. Typically, the mud is mixed at the surface and pumped downhole at high pressure to the drill bit through a bore of the drillstring. Once the mud reaches the drill bit, it exits through various nozzles and ports where it lubricates and cools the drill bit. After exiting through the nozzles, the “spent” fluid returns to the surface through an annulus formed between the drillstring and the drilled wellbore.
Furthermore, drilling mud provides a column of hydrostatic pressure, or head, to prevent “blow out” of the well being drilled. This hydrostatic pressure offsets formation pressures thereby preventing fluids from blowing out if pressurized deposits in the formation are breeched. Two factors contributing to the hydrostatic pressure of the drilling mud column are the height (or depth) of the column (i.e., the vertical distance from the surface to the bottom of the wellbore) itself and the density (or its inverse, specific gravity) of the fluid used. Depending on the type and construction of the formation to be drilled, various weighting and lubrication agents are mixed into the drilling mud to obtain the right mixture. Typically, drilling mud weight is reported in “pounds,” short for pounds per gallon. Generally, increasing the amount of weighting agent solute dissolved in the mud base will create a heavier drilling mud. Drilling mud that is too light may not protect the formation from blow outs, and drilling mud that is too heavy may over invade the formation. Therefore, much time and consideration is spent to ensure the mud mixture is optimal. Because the mud evaluation and mixture process is time consuming and expensive, drillers and service companies prefer to reclaim the returned drilling mud and recycle it for continued use.
Another significant purpose of the drilling mud is to carry the cuttings away from the drill bit at the bottom of the borehole to the surface. As a drill bit pulverizes or scrapes the rock formation at the bottom of the borehole, small pieces of solid material are left behind. The drilling fluid exiting the nozzles at the bit acts to stir-up and carry the solid particles of rock and formation to the surface within the annulus between the drillstring and the borehole. Therefore, the fluid exiting the borehole from the annulus is a slurry of formation cuttings in drilling mud. Before the mud can be recycled and re-pumped down through nozzles of the drill bit, the cutting particulates must be removed.
Apparatus in use today to remove cuttings and other solid particulates from drilling fluid are commonly referred to in the industry as shale shakers or vibratory separators. A vibratory separator is a vibrating sieve-like table upon which returning solids laden drilling fluid is deposited and through which clean drilling fluid emerges. Typically, the vibratory separator is an angled table with a generally perforated filter screen bottom. Returning drilling fluid is deposited at the feed end of the vibratory separator. As the drilling fluid travels down length of the vibrating table, the fluid falls through the perforations to a reservoir below leaving the solid particulate material behind. The vibrating action of the vibratory separator table conveys solid particles left behind until they fall off the discharge end of the separator table. The above described apparatus is illustrative of one type of vibratory separator known to those of ordinary skill in the art. In alternate vibratory separators, the top edge of the separator may be relatively closer to the ground than the lower end. In such vibratory separators, the angle of inclination may require the movement of particulates in a generally upward direction. In still other vibratory separators, the table may not be angled, thus the vibrating action of the separator alone may enable particle/fluid separation. Regardless, table inclination and/or design variations of existing vibratory separators should not be considered a limitation of the present disclosure.
Preferably, the amount of vibration and the angle of inclination of the vibratory separator table are adjustable to accommodate various drilling fluid flow rates and particulate percentages in the drilling fluid. After the fluid passes through the perforated bottom of the vibratory separator, it can either return to service in the borehole immediately, be stored for measurement and evaluation, or pass through an additional piece of equipment (e.g., a drying shaker, centrifuge, or a smaller sized shale shaker) to further remove smaller cuttings.
A typical vibratory separator consists of an elongated, box-like, rigid bed, and a screen attached to, and extending across, the bed. The bed is vibrated as the material to be separated is introduced to the screen. The vibrations, often in conjunction with gravity, move the relatively large size material along the screen and off the end of the bed. Liquid and/or relatively small sized material passes through the screen into a pan. The bed is typically vibrated by pneumatic, hydraulic, or rotary vibrators, in a conventional manner.
FIG. 1 shows a conventional vibratory shaker 1. Vibratory shaker 1 has a screen assembly 2 mounted in a vibratable screen mounting apparatus known as a basket 3. Screen assembly 2 may be of any type known to one of ordinary skill in the art including, for example, hookstrip or pretensioned. Basket 3 is mounted on four springs 4, two of which are shown, the other two of which are on the opposite side of basket 3. Additionally, four basket spring pads 9 are positioned on top of springs 4. Springs 4 are supported on four skid spring pads 10 disposed on a skid 6. Basket 3 is vibrated by a motor 5 and interconnected vibrating apparatus 8 which is mounted on basket 3 for vibrating basket 3 and screen 2. Elevator apparatus 7 provides for raising and lowering of basket 3 at one end.
Mounting basket 3 on springs 4 attached to skid 6 allows for a vibratory motion to be imparted to basket 3 relative to skid 6. However, heavy loads, including basket 3 and drilling material disposed thereon, may have to be supported by springs 4, and thus, springs 4 may be very rigid and resistant to movement. Such rigidity may result in requiring high forces in order to impart a vibratory motion to basket 3. Furthermore, applied energy may be lost to friction in springs 4, necessitating additional energy to impart vibratory motions. Also, springs 4 may become less rigid through use, diminishing the capability of springs 4 to function as expected. Thus, springs 4 may require maintenance and will eventually require replacement.
Accordingly, there exists a need for a vibratory shaker that may be constructed with more wear-resistant parts. Furthermore, there exists a need for a vibratory shaker having a basket that may be suspended above a skid without attachment through a rigid member, thereby vibrated by non-conventional methods.